HYDROCARBON AND HYDROSTATIC FLUID PRESSURE GRADIENT AND ITS APPLICATIONS

1. HYDROCARBON AND HYDROSTATIC FLUID PRESSURE GRADIENT AND ITS APPLICATIONS BY :ONWUAZOMBE TOBECHUKWU

2. OUTLINE • INTRODUCTION • FORMATION FLUID PRESSURE • METHODS OF MEASURING FORMATION FLUID PRESSURE • INTERPRETATION/ANALYSIS OF PRESSURE DATA • APPLICATIONS OF WFT PRESSURE PROFILE • COMPLEXITIES AND CHALLENGES • REFERENCE • CONCLUSION

3. INTRODUCTION • PRESSURE • Pressure is defined as force divided by area. The unit of pressure in the oil and gas field is psi, which stands for pounds per square inch. • For example, 3000 psi means 3000 lbs. of force over a square inch of area. • ……(1) • P =Pressure in psi • F = Force in lbs. • A = Area in square inches. Shallow- lower pressure Deeper- higher pressure Fig. 1.0. Pressure increases with depth in liquids Fig. 1.1. Pressure in solids

4. THE NATURE OF FLUIDS • The most important property affecting subsurface fluid behavior is density. • For any body of fluid, the internal pressure increases with depth in the body. • Fluid densities are often expressed in kilograms per cubic meter. • In the petroleum industry, fluid densities are commonly described on an API gravity scale in degrees. • API gravity = 131.5……(2) • To eliminate the inconvenience of working with different systems of units, we use the specific gravity of fluids. Table. 1.0. Density range of fluids in kg/m3 Fig. 1.2. Pressure-depth relationship within a single container

5. HYDROSTATIC PRESSURE • Hydrostatic pressure is the pressure of the fluid column exerted in static condition and in equilibrium with the surface pressure. • Hydrostatic pressure depends on the weight of the fluid (PPG)and true vertical depth (TVD) of the well. • In addition, 0.052 is a constant for conversion to psi. • The hydrostatic pressure can be calculated using the formula below • Ph= 0.052 TVD…….(3) • ring burial, normally pressured formations are able to Fig. 1.3. Hydrostatic pressure

6. HYDROSTATIC PRESSURE GRADIENT Fig. 1.4. Examples of hydrostatic pressure gradients for different fluids. • Hydrostatic pressure gradient (psi/ft.) refers to the pressure exerted by the column of fluid per foot. • For example, freshwater has a hydrostatic pressure gradient of 0.433 psi/ft., which means 0.433 psi of fluid column acts on 1ft. Fig. 1.5. Fluid columns and gradients showing principles for calculating pressure gradients from density and specific gravity

7. FORMATION PORE PRESSURE • This is the pressure of the naturally occurring fluid(s) in the pores of the rock. • It is the portion of the overburden pressure that is supported by the fluids in the pore spaces and not by the rock matrix • When formation pressure is approximately equal to the theoretical hydrostatic pressure for the given depth, formation pressure is said to be normal. • Normal pore pressure is usually expressed in terms of the hydrostatic gradient. Fig. 2.0. Illustration of porosity in rocks

8. NON-NORMAL FORMATION PORE PRESSURE • In any geological setting, the normal formation pressure will be equal to the hydrostatic pressure • Any deviation from the normal trend is called non-normal formation pressure. • Abnormal formation pressure is greater than normal for the depth of interest. Such formations are sometimes referred to as geopressured. • Subnormal formation pressure is less than normal for the vertical depth of interest due to production operations. Fig. 2.1. Pressure trend in sub-surface formations

9. CAUSES OF NON-NORMAL FORMATION PRESSURE Table. 2.0. Causes of non-normal formation pressures Fig. 2.2. Communication of the reservoir with the surface at an essentially higher elevation than ground level at the well site.

10. CAUSES OF NON-NORMAL FORMATION PRESSURE • Abnormal compaction occurs when the pore fluid sustains part of the overburden weight. Fig. 2.3. Changes in pore size and grain shape that occur as an unconsolidated sediment is buried and compacted.

11. CAUSES OF NON-NORMAL FORMATION PRESSURE Fig. 2.5. Reduction of pore space by formation of crystalline overgrowths on the grain surfaces Fig. 2.6. Osmosis can in theory create significant overpressures Fig. 2.4. Formations under a salt layer are usually overpressured Fig. 2.9. Addition of overburden can cause sub-normal formation pressures at time of drilling Fig. 2.8.Heating of the rock increases the pore fluid pressure since fluid volume increase is many times greater than the pore volume Fig. 2.7. Overpressure caused by infusion of gas from nearby coal seams or breakdown of organic matter

12. METHODS OF MEASURING FORMATION FLUID PRESSURE • Drillstem testing is carried out during drilling the well • A portion of a perforated drill pipe and packers is lowered into the well at the required depth • The packers seal the interval of interest by expanding to make a barrier between the borehole wall and drill pipe • A valve is then opened to allow any formation pressure and fluid present to enter the tool • A recorder in the tool makes a graph of the formation pressures. Fig. 3.0. The drillstem test

13. METHODS OF MEASURING FORMATION FLUID PRESSURE • Wireline formation testing (WFT) is carried out in an open hole during wireline logging operations • Some wireline tools include FIT, RFT and MDT • Samples of fluid and measurements of fluid pressures are taken. • Wireline formation test is not continuous like other forms of logging • It is carried out in the reservoir zone of the well at predetermined depths. Fig. 3.1. The RFT test

14. REPEAT FORMATION TESTER (RFT) • RFT Operation: • At the depth of interest, the tool initially takes drilling mud pressures before being attached to the wall of the borehole by a backshoe. • The measurement and sampling head consists of a packer that surrounds a probe which contains a piston. • The piston is pressed into the formation , then withdrawn to allow flow from formation to the tool. • A valve allows the chambers to be filled at different flow rates and the pressure is measured. Fig. 3.2. RFT operation. Fig. 3.3. RFT internal piping

15. INTERPRETATION/ANALYSIS OF PRESSURE DATA • Pressure-depth plots (P-D plots) are the most common interpretation tools used for WFT pressure data • This is done by constructing and interpreting scenarios from simple graphical plots of formation pressure against depth at which they are measured • Other methods of displaying data for interpretation include average pressure gradient plots, excess pressure plots, mud pressure versus formation pressure, pressure coefficient plotand density potential plot. Table. 3.0. WFT pressure data variation with depth

16. APPLICATIONS OF WFT PRESSURE PROFILES • Wireline formation pressure profiling is usually straight-forward, and at the simplest level can complement our other petrophysical tools in the following ways: • Fluid typing, via determination of the fluid pressure gradient • Fluid contact and free water level placement, via observation of pressure gradient changes • Reservoir connectivity/continuity, via identification of similar, but offset, pressure gradients. Fig. 4.0. Fluid typing and reservoir connectivity on a pressure-depth plot.

17. DETERMINATION OF FLUID TYPE • In virgin reservoirs, The observed pressure gradientsreflect the density of the original fluids. • Gradients displayed on P-D plots are related to the density of dominant moveable phases within the reservoir pore space • In case of a single (mobile) fluid, the relationship between (measured) pressure and (calculated) density in gm/cc is: • Fluid Density = ……(4) • Pressure gradient range for fluids: • Water : 0.411 to 0.520 psi/ft. • Oil : 0.25 to 0.35 psi/ft. • Gas : 0.02 to 0.10 psi/ft. Fig. 4.1. Reservoir fluid types

18. DETERMINATION OF FLUID TYPES Fig. 4.3. Well 01 penetrating reservoir P3 containing gas and oil Fig. 4.2. Well 01 penetrating reservoir P4 containing gas and water

19. DETERMINATION OF FLUID CONTACTS AND FREE WATER LEVEL Fig. 4.5. P-D plot for reservoir containing water, oil, and gas Fig. 4.5. P-D plot for reservoir containing water and oil Fig. 4.4. P-D plot for reservoir containing water and oil

20. IMPLICATION OF CAPILLARY PRESSURE IN RESERVOIRS • Free Water level is defined as the intersection of hydrocarbon pressure gradient and water pressure gradient. At free water level, Pc=0 • Where, Pc= Capillary pressure between hydrocarbon and water • Transition zone is the vertical thickness over which the water saturation ranges from 100% saturation to irreducible water saturation Swc • The OWCis defined as the uppermost depth in the reservoir where a 100% water saturation exists. Fig. 4.6. Water saturation distribution as a function of distance from the free-water level

21. IMPLICATION OF CAPILLARY PRESSURE IN RESERVOIRS Fig. 4.8. Capillary pressure variation with size of pore throat Fig. 4.7. Capillary pressure variation with size of pore throat • The minimum pressure required to displace the wetting phase from the largest capillary pore is called the displacement pressure Pd • Sands have large pore throats. Hence a small capillary pressure is required by the migrating oil to displace the water as compared to shale.

22. IMPLICATION OF CAPILLARY PRESSURE IN RESERVOIRS Fig. 4.9. Variation of transition zone with fluid gravity Fig. 4.10. Variation of transition zone with permeability • Alow API gravity oil reservoir with an oil-water contact will have a longer transition zone than a high API gravity oil reservoir. • A reservoir rock system with small pore sizes will have a longer transition zone than a reservoir rock system comprised of large pore size

23. IMPORTANCE OF FREE WATER LEVEL • Free water level determination has significant effect on initial hydrocarbon in place • Fluid contacts and FWL location in formations enable the calculation of the net rock volume(NRV) appearing in the formula: • HCIIP= (stb)……(5) • Even a few feet error in free water level determination will underestimate/ overestimate reserves heavily in case of large areal extant of reservoir. Fig. 4.11. Volumetricscalculation

24. DETERMINATION OF RESERVOIR CONNECTIVITY • If pressure-depth pairs from multiple wells obtained from a single reservoir fall on the same pressure gradient, reservoir connectivity is implied but not proven. • However, if slight offsets are observed in the hydrocarbon gradients between wells, compartmentalization is implied. Fig. 5.0. Four wells in a hydraulically connected oil-bearing sandstone compartment and the fluid pressures in different wells Fig. 5.1. Compartmentalized reservoir

25. DETERMINATION OF RESERVOIR CONNECTIVITY Fig. 5.2. Pressure-depth relationships within a single fluid network Fig. 5.3.Pressure-depth relationships when original single network system is subdivided into three separate, isolated systems

26. PRESSURE-DEPTH PLOT INTERPRETATION • Simplified examples of p-d plots of WFT data collected in a single wellbore • The normal hydrostatic gradient is shown by a dash blue line • Solid blue lines indicate aquifer gradients • Red lines indicate gas gradients • Green lines indicate oil gradients Fig. 5.4. Possible pressure profiles from a single wellbore

27. PRESSURE-DEPTH PLOT INTERPRETATION • Simplified examples of p-d plots of WFT data collected in a single zone from multiple wells • The normal hydrostatic gradient is shown by a dash blue line • Solid blue lines indicate aquifer gradients • Red lines indicate gas gradients Fig. 5.5. Possible pressure profile from multiple wells in a single zone

28. COMPLEXITIES AND CHALLENGES • Potential complexities and challenges of WFT data and pressure profile analysis include: • Integration of WFT and DST data • Confusion between FWL and fluid contacts • Supercharging • Inadequate raw data quality control • Effects of overpressure, depletion and hydrodynamics • Non-recognition of multiple compartments • Inconsistence with other geophysical logs Fig. 5.6. Results of quantitative log interpretation for a gas exploration well from Field A (well A2). The GWC is the intersection of the pressure gradients at 1158.4 m TVDSS

29. CONCLUSION • Pore pressures in most deep sedimentary formations are not hydrostatic instead they are overpressured and elevated even to more than double of the hydrostatic pressure • If the abnormal pressures are not accurately predicted prior to drilling, catastrophic incidents, such as well blowouts and mud volcanoes, may take place. • Pressure profile analysis using WFT pressure data has a number of potential applications in both development and exploration settings • A rigorous quality control process should always be implemented and the various complexities and interpretation options be kept in mind while manipulating the data.

30. REFERENCE • Applied Drilling Engineering by Adam T. Bourgoyne Jr, Keith K. Millheim, Martin E. Chenevert, F.S. Young Jr. • Applied Hydrodynamics In Petroleum Exploration Eric C. Dahlberg • The Practice Of Reservoir Engineering (1994)- Dake • Determination Of Oil And Gas Reserves ,1994 By The Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum, Calgary Section. • WFT Data And Pressure Profile Analysis: Applications, Complexities And Challenges By James Howes • Reservoir Engineering Handbook 4th Edition By Ahmed Tarek.H • Identification Of Fluid Contacts By Using Formation Pressure Data And Geophysical Well Logs Assoc. Prof. Dr. Bogdan-Mihai NICULESCU Ph.D. candidate Constantin • Testing, Testing 1,2,3 R E (Gene) Ballay, PhD 2008.

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